1. Field of the Invention
The present invention relates generally to geophysical exploration and more particularly to methods for accurately estimating fluid and overburden pressures in the earth""s subsurface on local, prospect and basin-wide scales.
2. Background of the Art
During drilling of a borehole, drilling fluids, usually referred to as xe2x80x9cmud,xe2x80x9d are circulated in the borehole to cool and lubricate the drill bit, flush cuttings from the bottom of the hole, carry cuttings to the surface, and balance formation pressures encountered by the borehole. It is desirable to keep rotary drilling mud weights as light as possible, but above the formation pore fluid pressure, to most economically penetrate the earth; heavier muds may break down rocks penetrated by the borehole and thereby cause loss of mud. Mud weight is carefully monitored and may be increased during drilling operations to compensate for expected increases in the formation fluid pressure. In some areas, however, there may be unexpected abnormal increases in pressure, with depth such that mud weight does not compensate pressure; the result can be blowout of the well.
Normal pressures refer to formation pressures that are approximately equal to the hydrostatic head of a column of water of equal depth. If the formation were opened to the atmosphere, a column of water from the ground surface to the subsurface formation depth could balance the formation pressure. In many sedimentary basins, shallow predominantly sandy formations contain fluids that are under hydrostatic pressure.
At a number of offshore locations, abnormally high pore pressures have been found even at relatively shallow sub-sea bottom depths (less than about 1500 meters). This could occur if a sand body containing large amounts of water is covered by silt or clay and buried. The dewatering of clays may result in the formation of relatively impermeable shale layers that slow down the expulsion of water from the underlying sand. The result of this is that the sand may retain high amounts of fluid and the pore pressure in the sand exceeds that which would normally be expected from hydrostatic considerations alone, i.e., the fluid pressure exceeds that which would be expected for a column of water of equivalent height. This phenomenon of overpressuring is well known to those versed in the art and is commonly referred to as xe2x80x9cgeopressure.xe2x80x9d
It is desirable to set casing in a borehole immediately above the top of a geopressured formation and then to increase mud weight for pressure control during further drilling. Setting a casing string which spans normal or low pressure formations permits the use of very heavy drilling muds without risking breaking down of borehole walls and subsequent lost mud in the shallower interval. On the other hand, should substitution of heavy drilling mud be delayed until the drill bit has penetrated a permeable overpressurized formation (e.g., sandstone), loss of well control or blowout may occur.
In areas where there is reason to suspect existence of such high pressure formations, various techniques have been followed in attempts to locate such geopressure zones. For example, acoustic or electric logs have been run repeatedly after short intervals of borehole have been drilled or are acquired using measurement-while-drilling techniques, and a plot of acoustic velocity or electrical resistance or conductivity as a function of depth has been made. Abnormal variations of acoustic velocity and/or electrical properties obtained by logging may indicate that the borehole has penetrated a zone of increasing formation pressure. Such techniques are very expensive and time-consuming and cannot predict what pressures will be encountered ahead of the bit.
Several methods are known in the art for estimating pore pressures in formations, using well log data and also from seismic survey information. One such method is well known in the art as the xe2x80x9cEatonxe2x80x9d method, and is described at Eaton, xe2x80x9cThe Equation for Geopressure Prediction from Well Logsxe2x80x9d SPE 5544 (Society of Petroleum Engineers of AIME, 1975). The Eaton method of determining pore pressures begins with determination of the so-called xe2x80x9cnormal compaction trend linexe2x80x9d based upon sonic, resistivity, conductivity, or d-exponent data obtained by way of well logs. The normal compaction trend line corresponds to the increase in formation density (indicated by sonic travel time, resistivity or conductivity) that would be expected as a function of increasing depth due to the increasing hydrostatic pressure that forces fluids out from the formations and thus decreases the sonic travel time (increases the velocity), assuming the absence of geopressure. This normal compaction trend line may be determined solely from the sonic travel time, conductivity, or resistivity well log data, or may be adjusted to reflect extrinsic knowledge about the particular formations of interest. The Eaton method calculates pore pressure by correlating the measured density information, expressed as an overburden gradient over depth, to deviations in measured sonic travel time, (or electrical resistivity or conductivity) from the normal compaction trend line at specific depths. The pore pressure calculated from the Eaton equations has been determined to be quite accurate, and is widely used in conventional well planning.
Specifically, the Eaton method determines a pressure gradient according to the relation                               G          p                =                              G            0                    -                                                    (                                                      G                    0                                    -                                      G                    n                                                  )                            ⁡                              [                                                      Δ                    ⁢                                          xe2x80x83                                        ⁢                                          t                                              n                        ⁢                                                  xe2x80x83                                                ⁢                        o                        ⁢                                                  xe2x80x83                                                ⁢                        r                        ⁢                                                  xe2x80x83                                                ⁢                        m                        ⁢                                                  xe2x80x83                                                ⁢                        a                        ⁢                                                  xe2x80x83                                                ⁢                        l                                                                                                  Δ                    ⁢                                          xe2x80x83                                        ⁢                                          t                                              o                        ⁢                                                  xe2x80x83                                                ⁢                        b                        ⁢                                                  xe2x80x83                                                ⁢                        s                        ⁢                                                  xe2x80x83                                                ⁢                        e                        ⁢                                                  xe2x80x83                                                ⁢                        r                        ⁢                                                  xe2x80x83                                                ⁢                        v                        ⁢                                                  xe2x80x83                                                ⁢                        e                        ⁢                                                  xe2x80x83                                                ⁢                        d                                                                                            ]                                      3                                              (        1        )            
where Gp is the formation pressure gradient (psi/ft), Go is the overburden gradient, GN is the normal gradient, xcex94tnormal is the normal transit time and xcex94tobserved is the observed transit time.
However, application of the Eaton method has been limited to the immediate locations of existing wells, as it depends on well log data. It is of course desirable to estimate pore pressure at locations at the sites of proposed new wells, and thus away from currently existing wells, particularly to identify locations at which production will be acceptable at a low drilling cost (e.g., minimal use of intermediate casing). In addition, knowledge of pore pressure at locations away from existing wells enables intelligent deviated or offset drilling, for example to avoid overpressurized zones.
Kan (U.S. Pat. No. 5,130,949) teaches a method in which seismic data is combined with well log data to generate a two-dimensional geopressure prediction display; this permits deviated and horizontal well planning plus lithology detection. Shale fraction analysis, compaction trend, and seismic velocity may be automatically or interactively generated on a computer work station with graphics displays to avoid anomalous results. Corrections to velocity predictions by check shots or VSP, and translation of trend curves for laterally offset areas increases accuracy of the geopressure predictions. In particular, Kan ""949 determines the transit time from sonic logs for compressional waves in predominantly shaly sections and expresses the pore pressure gradient (PPG) in terms of the transit time departure from the compaction trend line, xcex4xcex94t, as
PPG=0.465+C1(xcex4xcex94t)+C2(xcex4xcex94t)2xe2x80x83xe2x80x83(2)
Coefficient C1 typically varies from 0.002 to 0.02 if the transit time is expressed in microseconds per foot and the PPG is measured in psi/ft. C2 may be positive or negative.
Kan ""949 also teaches the use of vertical seismic profile (VSP) data for calibration of the sonic log data. Kan (U.S. Pat. No. 5,343,440) and Weakley (U.S. Pat. No. 5,128,866) further teach the use of coherency analysis of surface seismic data for determination of interval velocities.
Scott (U.S. Pat. No. 5,081,612) teaches a variation of the Eaton method in which an equation of the form
Vc=V1(1xe2x88x92a1Lxe2x88x92a2xcfx86+a3P)xe2x80x83xe2x80x83(3)
where a1, a2 and a3 are constants, V1 is a constant, Vc is calculated velocity, L is the lithology of the formation, xcfx86 is the porosity and P is the effective pressure (difference between the overburden pressure and the formation fluid pressure). The compaction of the sediments is governed by an equation of the form
xcfx86=xcfx860exe2x88x92a4Pxe2x80x83xe2x80x83(4)
A reference model for the sedimentary basin is developed assuming compaction under hydrostatic pore pressure. A reference effective pressure and a reference velocity profile are obtained. An iterative procedure is used in which the lithology may be varied with depth and the reference velocity profile is compared to a velocity profile obtained from seismic data.
In addition to undercompaction, Bowers (U.S. Pat. No. 5,200,929) discusses a second cause of overpressuring. Abnormally high pressure can also be generated by thermal expansion of the pore fluid (xe2x80x9caquathermal pressuringxe2x80x9d), hydrocarbon maturation, charging from other zones, and expulsion/expansion of intergranular water during clay diagenesis. With these mechanisms, overpressure results from the rock matrix constraining expansion of the pore fluid. Unlike undercompaction, fluid expansion can cause the pore fluid pressure to increase at a faster rate than the overburden stress. When this occurs, the effective stress decreases as burial continues. The formation is said to be xe2x80x9cunloading.xe2x80x9d Since sonic velocity is a function of the effective stress, the velocity also decreases and a xe2x80x9cvelocity reversal zonexe2x80x9d develops. A velocity reversal zone is an interval on a graph depicting sonic velocity as a function of depth along a well in which the velocities are all less than the value at some shallower depth.
A large portion of the porosity loss that occurs during compaction is permanent; it remains xe2x80x9clocked inxe2x80x9d even when the effective stress is reduced by fluid expansion. A formation that has experienced a greater effective stress than its current value will be more compacted and have a higher velocity than a formation that has not. Consequently, the relationship between sonic velocity and effective stress is no longer unique when unloading occurs. In other words, for every effective stress, there is no longer one unique sonic velocity. The sonic velocity follows a different, faster velocity-effective stress relationship during unloading than it did when the effective stress was building. This lack of uniqueness is called xe2x80x9chysteresis.xe2x80x9d Since fluid expansion causes unloading, while undercompaction does not, hysteresis effects make the sonic velocity less responsive to overpressure generated by fluid expansion. As a result, the pore fluid pressure corresponding to a given sonic velocity at given depth within a velocity reversal zone can be significantly greater if the overpressure was caused by fluid expansion rather than undercompaction. Therefore, the sonic velocity of an overpressured formation is indirectly dependent upon both the magnitude and the cause of overpressure. To account for different causes of overpressuring, Bowers teaches the use of two different velocity-effective stress relations: one relation applies when the current effective stress is the highest ever experienced by a subterranean formation and a second relation that accounts for hysteresis effects is used when the effective stress has been reduced. Pore fluid pressure is found by subtracting the computed effective stress from the overburden stress. Bowers uses a relationship of the form
V=C+A["sgr"max("sgr"/"sgr"max)(1/U)](1/B)xe2x80x83xe2x80x83(5)
for the effect of unloading. In eq. (5), max is the maximum stress to which the rock has been subjected. The unloading curve parameter U is a measure of how plastic the sediment is, with U=1 and U=∞ defining the two limiting cases. For U=1, the unloading curve is the same as the loading curve whereas for U=∞ greater than  the velocity remains fixed at a value Vmax determined by the stress, max.
The invention provides a methodology, process and computer software for the prediction of fluid and rock pressures in the subsurface using geophysical and geological data. The method includes techniques for velocity analysis from seismic data that are used to drive the pressure prediction, as well as an integrated approach to deriving pressure data that is new and novel in nature and scope. The invention addresses the prediction of pressure information for three scales of analysis including (1) basin-scale (10-500 km spatial lengths) analysis of hydrocarbon systems, (2) prospect-scale (1-10 km spatial length) analysis of fluid flow that can be used to analyze fluid movement in localized areas, and (3) prediction of pressure conditions at a specific location (0-1 km spatial length) where a well is to be drilled. The results of the prediction can be utilized in a range of other applications that address the fundamental behavior of hydrocarbon systems and can improve the ability to find commercial quantities of hydrocarbons in the subsurface. The results can also be used to design and optimize well planning.
The technique and computer software estimates fluid pressure (from overburden stress and effective stress where effective stress is a function of seismic velocity), fracture pressure gradient, overburden pressure (from integration of density logs, using the Gardner-Gardner-Gregory relations with velocity estimates from sonic logs or seismically derived seismic velocities, or a combination of seismic data and Gravity/Magnetic data), effective stress (from seismic data) and porosity (from seismic data) for well planning, basin-scale pressure fields and prospect-scale pressure fields, and also can generate predictions and interpretations that are applicable to:
hydrocarbon maturation
fluid migration
lateral and vertical seal rock integrity
reservoir-specific lateral pressure changes
fault-seal properties
effects of hydrocarbon reservoirs on pressure prediction
effects of anomalous lithologic intervals on pressure prediction and overburden estimation
The software provides an operating environment in which all data pertinent to predicting subsurface rock and fluid pressures can be stored, displayed in tabular and graphical forms, analyzed, calibrated and used in the prediction process.
The software provides the user with three pressure prediction methods, the Eaton method, the effective stress method, and the equivalent depth method, and allows a range of curve fitting options for each method including linear, power law, exponential, and quadratic functions.
The computer software allows large amounts of seismic velocity data to be processed and analyzed with the results being displayed as a color underlayment on a display of a migrated or stacked seismic section. The software allows the results from an entire 2-D seismic line, a set of multiple 2-D seismic lines, or a 3-D seismic volume to be displayed with the related seismic and well data. In addition to migrated or stacked seismic section displays, the software allows displays based on velocity data, acoustic impedance data, density data, and other attributes such as frequency displays, amplitude displays, phase displays, and other common derivatives created from analysis and inversion of the seismic data. In particular, certain displays such as acoustic impedance, which are generated from post-stack inversion and pre-stack inversion, can be used in the calibration and prediction steps of pressure prediction because of their usefulness as indicators of lithology variation. Likewise, amplitude and frequency displays can be used in the calibration and prediction steps because they identify anomalous zones where hydrocarbons are present in the subsurface which can cause anomalies in the data that would result in erroneous pressure estimates.
The computer software allows calibration functions and prediction computations to be constrained by geologic boundaries such as horizons and faults so that multiple calibrations can be applied to areas with complex geological loading histories.
The technique and computer software use multiple data types and handle them in an integrated fashion. The data include seismic and well-based velocity information (such as from VSP data and sonic logs), geologic boundaries such as horizons and faults mapped from the seismic data, pressure data from wellbores including formation fluid pressures and fracture pressures based on Leak Off Tests (LOT""s), well log data, and digital seismic data in standard industry formats. LOT""s are described further below.
The computer software has the ability to read data in generic text formats and in standard formats such as would be generated by well logging contractors, seismic processing contractors, or commercial seismic interpretation systems. The data can be displayed in various tabular and graphical forms. The software provides display capability that includes interactive viewing and analysis of multiple data types simultaneously so that the user can evaluate all of these data at once. Related data can be calibrated using a variety of functional equations that are appropriate for pressure prediction.
The technique and software contains a calibration module that includes a method and ability to display, edit, and datum a variety of well logs, and fit calibration curves to the logs or estimate equation coefficients and exponents for a specific prediction method (such as the Eaton method, the Bowers method, the effective depth method). The displays include depth versus log value displays along with cross-plot displays for various log parameters and plots of velocity versus effective stress. The depth and crossplot displays are linked interactively to a scrollable coefficient display window that allows the user to modify the coefficients of the equation and observe the resulting change in the graphical display in real time. The calibrations can be performed using all of the methods and equations known to experts versed in the art including but not limited to the Eaton method, the effective stress method and the equivalent depth method. The calibration module includes a method and ability for using a variety of mathematical fits including linear, exponential, power law and quadratic forms that encompass the full range of possible mathematical forms for pressure relationships in the subsurface. The calibration module allows the calibration to equation form of effective stress versus velocity, velocity versus density, velocity versus porosity, density versus porosity, overburden versus depth, and fracture gradient versus depth. These equations can be defined for any subset of a set of well log data that the user selects, for example, on the basis of a lithological or other discriminator applied to the data, or by selecting a specific geological interval that is defined by certain characteristics and specific mapped geologic boundaries. The calibration of fracture gradient can be performed using LOT data and one of three methods which include (i) fitting a function to the LOT data from available local well control; (ii) determining a function based on a percentage of the overburden stress that honors regional data; or (iii) applying an appropriate stress ratio (Ko) as defined by Matthews and Kelly (xe2x80x9cHow to Predict Formation Pressure and Fracture Gradientxe2x80x9d (Oil and Gas Journal, v. 5, no. 8, 1967)).
The calibration module also allows the calibration of unloading hysteresis for zones where the velocity has decreased due to secondary pressure conditions. This is determined by fitting the velocity and stress data for the unloaded zone to a relationship for unloading.
The calibration module includes interactive graphical displays of velocity, pore pressure, effective stress, overburden and fracture gradient versus depth and or time with horizons and faults posted on the displays.
The technique and software contains a prediction module that includes a method and ability to display seismic velocity data along with displays of stacked or migrated seismic data with horizons, faults and an attribute of choice from a range of velocity and pressure data types plus the same calibration displays above.
The prediction module applies the calibration curves or equations to the data at each seismic velocity location in order to calculate such attributes as pore pressure, effective stress, fracture gradient, overburden, and porosity.
The prediction module can store in memory the calculated attributes as functions of time or depth for later display and analysis.
The prediction module displays the stacked seismic data with interpreted horizons and faults, and pore pressure or other attribute underlayment in color during the analysis that can be used interactively during the prediction of pressures.
The prediction module includes interactive graphical displays of velocity, pore pressure, effective stress, overburden, density, porosity and fracture gradient versus depth and or time with horizons and faults posted on the displays, seismic sections and base maps.
The technique and software contains a method and ability to generate digital files of the predicted attributes in appropriate formats for other mapping packages, and transfer these files to a computer medium appropriate for transfer to other computer software. Prediction results can be output in time or depth for subsequent import into seismic interpretation systems.
The software contains a method and has the ability to display seismic scale overlay plots of pressure and other attributes and depth plots for each location analyzed. The predicted attributes include, but are not limited to the following:
pore pressure as a function of depth or time
effective pressure as a function of depth or time
overburden as a function of depth or time
fracture gradient as a function of depth or time
porosity as a function of depth or time
excess pressure as a function of depth or time
unloading pressure as a function of depth or time
Predicted pressure-related attributes can be displayed in units of pressure (e.g., psi) or pressure gradient (e.g., psi/ft or ppg).
The technique and software includes a method and ability to use velocities from one or more sources including but not limited to one or more of the following:
stacking velocity data
coherency inversion velocity data
pre-stack inversion P-wave velocity data
post-stack inversion P-wave velocity data
pre-stack inversion S-wave velocity data
post-stack inversion S-wave velocity data
shear-wave stacking velocity data
tomographic P-wave velocity data
tomographic S-wave velocity data
VSP velocity data
VSP look-ahead inversion
sonic logs
dipole sonic logs
mode-converted shear wave velocity data
combined Vp and Vs inversion
The method includes use of all of the above velocity types for pressure prediction with horizon-keyed constraints. The technique also claims first use of some of the velocity types above without horizon-keyed constraints. These include the following:
pre-stack inversion P-wave velocity
post-stack inversion P-wave velocity
pre-stack inversion S-wave velocity
post-stack inversion S-wave velocity
shear-wave stacking velocity
tomographic P-wave velocity
tomographic S-wave velocity
VSP look-ahead inversion
dipole sonic logs
mode-converted shear wave velocity
combined Vp and Vs inversion
The technique and software includes a method and ability for picking seismic stacking velocities using a horizon-keyed and fault-keyed approach. This means that, unlike conventional seismic-velocity picking methods that use the strongest semblances from the seismic data, the velocities are picked to honor the formation geological and structural boundaries defined by the lithological rock units and such features as faults and anomalous body boundaries in 2-D or 3-D.
The technique and computer software includes a method to isolate the velocities for geologic intervals that contain hydrocarbons or lithologies other than those that are appropriate to use in the prediction step. This same method can be used to isolate the velocities of reservoirs and seal rocks that are not in equilibrium with the encasing seal rocks. This method requires velocity types that have sufficient resolution to accurately detect the distinct velocities in these zones. In this situation, the software allows the user to identify the zone or zones to be excluded, and the software removes this value from the calculations in the prediction step.
The software also allows the data from anomalous zones to be saved to a separate data file that can be analyzed separately for pressures in specific zones.
The method can also be applied to pressure prediction from the results of seismic analysis on the geologic hazard called shallow water flows as defined in U.S. patent application Ser. No.09/433,446 filed on Nov. 4, 1999 having the same assignee as the present application and the contents of which are fully incorporated herein by reference.
The method of excluding zones from the pressure analysis can be applied for any velocity data types that may be developed and used in other software that are already known to those versed in the art of pressure prediction.
The technique and software includes a method and ability to change the overburden and fracture gradient calculated for a given location based on one of three schemes. In the first scheme, the analyst identifies an anomalous density zone that may be caused by the presence of either anomalous rocks or fluids, and inputs to the software the anomalous density value for that zone. The software inserts this new density for the interval into the overburden function for the location being evaluated, and re-calculates the overburden function using this zone in place of the densities from the reference function that was used originally to determine the overburden stress versus depth. This new function with the anomalous zone is used only at the location where the anomalous formation was identified. By doing this at each location where the anomalous zone is observed, the user may build an overburden and fracture gradient profile that honors the actual geology in 3 dimensions rather than relying on a 1D density function determined from a single well location that does not always represent the subsurface at other locations.
The second scheme for changing the overburden and fracture gradient is to use 2D or 3D density models determined independently from the inversion of vector and tensor gravity and vector and tensor magnetic data and to integrate these models in 2D or 3D to predict overburden in an area where pressures are to be predicted. This can include, but is not limited to the inclusion of 1D well density data for calibration of the gravity and magnetic data. Such methods of determination of overburden are discussed, for example, in U.S. patent application Ser. Nos. 09/285,570, 09/399,218, and 09/580,863.
The third scheme for changing the overburden and fracture gradient is to use density values predicted in 2D or 3D seismic data using simultaneous inversion of multicomponent PP and PS data or the density values predicted from pre-stack inversion. In this case, the seismic data is calibrated with density data from well control, and the 2D or 3D seismically derived density values are used at each location to calculate overburden and fracture gradient.
The technique and software contains a method and ability for creating and applying calibration functions that are controlled by and keyed to specific geologic intervals in the subsurface. These are usually applied to a geologic interval of specific age that is observed to occur across a specific area of the subsurface and has a distinct pore pressure calibration that is different from intervals above and below it in the subsurface. The method and ability allows the user to identify interpreted horizons to which the calibration is keyed and limits the application of the calibration to those horizons.
The method allows the user to use more than one active calibration at one time and the computer software splices these multiple calibrations together in the displays so that the user can simultaneously produce an integrated prediction for multiple zones with different calibrations. This multiple-zone calibration and prediction also includes the application of unloading parameters that can be specified for each calibration zone.
The technique and software includes interactive help menus that guide the interpreter through the process and method for performing pressure prediction. The help menu is divided into a methods tutorial and a hands-on help manual that defines and specifies what each module and function in the software actually does.
The technique and software includes a method of designing and applying a transformation function to data sets that are referenced to different map coordinate systems, including but not limited to UTM, shot point and line number, inline number and cross-line number, and state plane systems, such that all data can be referenced to a common coordinate system. Precise design and application of the transformations are facilitated by real-time parameter iteration made possible by concurrent examination of a base map display together with access to the transformation menu.
The technique and software includes a method of organizing data in a hierarchical structure. At each level of the hierarchy, one and only one set of data can be active. Within the active data set, multiple data elements can be selected for graphical and computational purposes.
The technique and software includes a method to automatically propagate the effects of interactive editing of calibration functions to those graphical displays that depend on the edited function. This capability includes but is not limited to real time updating of calculated effective stress, normal trend velocity, and pore pressure values in the calibration module in response to edits to the velocity versus effective stress calibration function, and updating the color underlay displays in the seismic section display in response to edits to parameters in the prediction module.